- July 31, 2016
- Posted by: Art Berman
- Category: The Petroleum Truth Report
Pioneer CEO Scott Sheffield made headlines last week when he claimed that his company’s Permian production costs “…can compete with anything that Saudi Arabia has.”
Is that a lie?
Pioneer’s Q2 2016 Earnings presentation shows that production costs for Permian basin horizontal wells are $2.25 per BOE (Figure 1).That cost cannot be verified because only company-wide production costs are included in the company’s 10-Q Quarterly Report.
The footnote in Figure 1 indicates that its stated production costs are untrue because they do not include all production costs. A lie is not a lie if you tell everyone that it is a lie.
By including the next line item “Production and ad-valorem taxes,” production costs become $4.13 instead of $2.25 per BOE. As Figure 1 shows, Pioneer’s overall production costs are $6.66 per BOE.
In fact, Pioneer’s total variable costs for the second quarter of 2016 were almost $18 per BOE (Table 1).This is the standard method to evaluate a company’s costs. It does not include considerable expenses for salt-water disposal because they are not mentioned in the company’s 10-Q.
Pioneer’s realized price for the first half of 2016 was $28.95 per BOE so the truth is that the company only has about $10 of margin before major capital expenditures of $7 million to drill and complete each well, much less pay royalties and income taxes!Break-even price for Pioneer’s average Trend Area-Spraberry well is about $52 per BOE. I’m sure the Saudis are scared to death about that.
Pioneer has “cherry-picked” the very best of their production and focused only on its production expenses thereby excluding 85% of its stated variable costs—to what end? Pioneer is a solid company that compares favorably to its competitors. After a rough first quarter for all companies, performance improved markedly in the second quarter and first half of 2016 (Figure 2).
The company outspent cash flow by 2-to-1, down from almost 5-to-1 in the first quarter. Debt-to-cash flow moved back within today’s bank-risk tolerance of less than 4-to-1 after exceeding 8-to-1 in the previous quarter. Why couldn’t Sheffield have pointed to this data as evidence that Pioneer is a strong performer among the shale players?
Sheffield is known for grandiose flights of fantasy. In 2013, he stated “The Spraberry Wolfcamp could possibly become the largest oil and gas discovery in the world,” comparing it to Ghawar, the world’s largest oil field. A year ago, Pioneer published a news release claiming Spraberry Wolfcamp “EURs averaging approximately 1 MMBOE, with IRRs averaging 50% to 60% at current strip commodity prices” that were around $45 per barrel. My work indicates an average EUR for those horizontal wells of approximately 300,000 BOE and financial results for Pioneer hardly reflect the returns stated in that release.
No credible oil and gas analyst believes those claims any more than recent statements that Pioneer’s well costs can compete with Saudi Arabia.
The shale gas and tight oil companies have developed a culture of exaggeration and misrepresentation. They have consistently tried to make the ludicrous case that a terrible reservoir and super-expensive technology can somehow out-perform much cheaper wells and better reservoirs in conventional plays.
It’s an unnecessary case to make because we’ve been out of those better, cheaper plays in the U.S. for decades. But, once you get started with embellishment, it leads to deception and then, it’s hard to remember what the truth is or even why you’re telling such unbelievable stories in the first place.
Investors play a role too. Many prefer a make-believe reality where America is great again, and they can dream of making crazy profits like in the good old days.
Seventy percent of Pioneer’s production is in the Permian basin (Table 2) and 80% of Permian production is from horizontal wells. So, 55% of Pioneer’s production is from the same subset of wells that Sheffield says can compete with Saudi Aramco.
If I were a Pioneer investor, I would ask Scott Sheffield at the next earnings call why he doesn’t just sell all of the company’s assets except horizontal wells in the Permian basin. Then we will find out if his comments are a lie or not.
I had a good old chuckle when I read this bit of news. I’m glad you covered how untrue it is in the media. It’s good that things like this can be read widely.
Art:
There needs to be a push with the SEC to require these companies to attach payout statements for their wells to their SEC filings.
These guys never talk about well payout, which is the true measure of profitability.
I haven’t seen any PXD payout statements, but I have seen them for a few of CLR’s Bakken wells. After reviewing these, I see why they are not generally shared, and LTO well payout is not discussed.
Spraberry wells, such as PXD’s, drop below 100 gross barrels per day quickly. Given royalties in the Permian are many times 25%, once wells hit this mark, not a lot of cash flow.
By the way, do the EUR put out by the companies include the royalty’s share? If so, why? I have seen royalties ranging from .125 to .40 in shale, so non disclosure of royalty burden is also a problem.
Someone is in cloud cuckoo land.
http://www.telegraph.co.uk/business/2016/07/31/texas-shale-oil-has-fought-saudi-arabia-to-a-standstill/
This $2.25 rubbish was dutifully reported by Ambrose Evans Pritchard in the Daily Telegraph today.
http://www.telegraph.co.uk/business/2016/07/31/aep-us-shale-producers-weather-oil-price-storm/
“Scott Sheffield, the outgoing chief of Pioneer Natural Resources, threw down the gauntlet last week – with some poetic licence – claiming that his pre-tax production costs in the Permian Basin of West Texas have fallen to $2.25 a barrel.”
The standard of modern ‘journalism’ is absolutely shocking. In the old days a supposed business and financial journalist might have done some checking themselves and at least look at Pioneer’s accounts to verify such claims. If their production costs were as low as $2.25 and their average revenue for the period was $41.43 then they must have been earning $bucketloads and be absolutely swimming in money. The accounts indicate the opposite.
I see you worked out that Pioneer’s breakeven oil price was $52 a barrel. This figure is backed up by their accounts for 2016.
http://investors.pxd.com/phoenix.zhtml?c=90959&p=irol-newsArticle&ID=2161096
From their accounts they made a loss of $268,000,000 for Q2 of 2016 against a loss of $267,000,000 in Q1 2016. This suggests losing money is pretty much business as usual for Pioneer, but that’s what we have come to expect in the new normal.
They produced 233,000 boepd in Q2 which equates to a loss of $12.76 per barrel. Their realized price in Q2 was $41.43. This means that in Q2 they needed an oil price of $54.19 just to break even which pretty much fits in with your cost assessment of $52.
The fiction of low cost production is maintained using non_GAAP EBITDA accounting practices by which they handily exclude the costs of actually drilling their wells and their associated asset depreciation.
On the depletion front, AEP reports
“The “decline rate” of production over the first four months of each well was 90pc a decade ago for US frackers. This dropped to 31pc in 2012. It is now 18pc. Drillers have learned how to extract more.”
I didn’t think that a decade ago wells depleted 90% in four months. I thought it was more like 60-75% over 12 months. Even so this newly invented 18% quarterly depletion rate still annualizes at 72%. It seems rather dubious how they seem to be re-writing the history of depletion in order to suggest that something revolutionary has taken place to halt decline when it has not.
Simon and Trevor,
Ambrose Pritchard-Evans sees the shale plays as a 1960s love-in experience like Woodstock. I cannot explain his stunningly biased reporting or why The Telegraph provides him with a platform except that he must sell newspapers for them.
The cost of producing a barrel of oil is 4-times higher in real dollars today compared with 20 years ago. This is the cost of technology and the poorer performance of poorer reservoirs. There isn’t a lot of choice because the cheap, conventional plays are depleting and what remains to be found is too small to meet the world’s consumption needs.
You can dress it up or down but that’s the truth about our primary source of energy in the world today. Some will agree and say, That’s why we must rush to renewable energy. But renewable energy is at least as expensive and has other problems like intermittency and low-energy density. It’s promoters will dress it up and focus on falling costs and growing installed capacity but it is only possibly a solution to high energy costs by comparison to other unaffordable sources of energy like unconventional oil.
Guys like Pritchard-Evans either don’t know enough about energy or don’t care so they merrily encourage the What, me worry? approach that says technology will fix everything and no one needs to change their behavior and the economy will be fine.
All the best,
Art
” A lie is not a lie if you tell everyone that it is a lie”…. Sorry Art, but I have to steal that line 🙂
“It does not include considerable expenses for salt-water disposal” SWD is the elephant in the room. First, it costs based on volume, and that cost is increasing as complaints about pollution (imaginary or not) and earthquakes (not imaginary) arise. I believe the increase in drilling in the STACKS play in Blaine and Kingfisher counties and the subsequent increase in offers to lease and or sell minerals there is a result of salt water issues being muted compared to the old Sooner Trend (Miss.) play. Just to the north and east where earthquakes are happening daily there is much less activity and development has slowed. But many of these wells are operating with a 10% oil cut. Operators are disposing of thousands of gallons of water to get a very few barrels of oil. That cost in many wells exceeds the value of the oil. With weakening prices, those wells will have to be shut it or operate at a loss. And the threat that SWD wells will be shut in or much reduced take due to earthquakes is a very real possibility.
Terrel,
Thanks for that useful information from the field. Salt-water disposal is almost impossible to evaluate quantitatively because the states do not require that operators report those volumes–no tax revenues from water. I know the water cuts are huge in the older basins–Anadarko and Permian mainly–and the costs to haul the water are high but I don’t know the volumes.
Feel free to steal my lie statement.
Art
Art,
Appreciate your independent, in depth analysis.
As a lay person, please explain what you get and Wood McKenzie and Rystad don’t when it comes to tight shale breakeven costs? Ref. yesterday’s (7/31/16, on the web) article in the London Telegraph by Ambrose Evans-Pritchar
Steven,
I respect Woodmac and Rystad but the companies in the plays are their clients. It’s like Moody’s and Standard and Poors’ AAA ratings on 2005-2008 securitized mortgages. If they don’t give the right rating, the client will give the business to a company that will.
There are at least 3 ways to get the story wrong.
The first and main way is to get the average well EUR/reserves wrong and consulting companies rarely show how they do this. We always show examples of our decline-curve analysis so people can see how we do it. Do these consultancies get the EURs from the companies or do they work through the production data themselves? For years, the industry and engineering companies dismissed our EUR work in the Barnett, Fayetteville and Haynesville shale plays. Now, the Barnett and Fayetteville plays are dead and the Haynesville should be–all are in serious decline after a handful of years when the experts said they would last for decades. Judge for yourself.
The second major way get it wrong is to exclude costs like interest expense, G&A (overhead) and other fundamental costs of doing business. A related problem is to use the WTI or Henry Hub benchmark prices and not the wellhead prices for the plays.
The third way is to convert gas to barrels of oil equivalent based on energy content (6:1) vs value (15-20:1). The gassier the play, the more difference this makes. Also, it is common to count a barrel of NGL as a barrel of oil equivalent when the value is about 30%.
My advice is to compare the evaluations of the various companies and experts with the financial performance of the key operators in the plays. If, in this case Woodmac’s and/or Rystad’s analysis says that the Permian plays are commercial at some oil price, look at Pioneer, Apache, Concho, Parsley, Energen, EOG, Cimarex, etc on Google Finance and see how their capex/cash flow and debt/cash flow look. I showed charts taken from that data in my last post. Some–Cimarex, EOG–are better than others but most look terrible. Ask why the rosy evaluations by Woodmac, etc. are not reflected in the balance sheets and income statements of the companies that lead the plays.
Then, decide.
All the best,
Art
I work for a major – and read your posts with great interest. I feel that you have an extremely valuable insight into the industry in general.
I also use consultancy services such as IHSE and Woodmac as part of my job.
I do not know but believe that these consultancies rely on company reports for their data, with maybe a bit of light checking rather than detailed independent analysis. They probably do not have the level of engineering expertise to do an extremely detailed job, few people do. These do make mistakes in the conventional world in which I work therefore I expect some errors to creep in in the unconventionals as well.
In terms of keeping the clients happy, like the rating agencies before the banking crisis. I do not really buy this, These companies have made some very critical comments on their proprietary reports about pretty much every company out there and they would rapidly lose credibility if they talked up a play or company in order to sugarcoat. An honest mistake is another matter
In terms of excluding G&A , Interest expenses etc which are as you say a fundamental part of business, these items are excluded from play analyses but included in the corporate analyses. This is on the assumption that the normal costs of doing business would be paid anyway and are not a direct part in the decision to invest in a well, field or any other project. G&A expenses are typically about 10-15% of turnover for most operators ( as against 50-60% for most other industries) which makes the staff cuts in operating companies all the more painful.
The gas streams, NGL streams etc are counted separately for economic analysis with their own price decks
hope this helps
Aslan,
Thanks for your comments.
I agree that Woodmac does make some critical comments, but fewer from IHS. I know and respect the people at these consulting companies but I remain confused by their consistent optimistic forecasts.
Economics that exclude costs are bogus no matter how you try to justify that approach.
Woodmac says that Texas tight oil plays break even at $41 per barrel. I promise you that none of the leading operators in the Permian and Eagle Ford plays are breaking even below $52 per barrel and most need at least $60. So, by excluding costs, Woodmac has provided a meaningless number that only serves to lower market expectations of price.
The idea that G&A, interest, etc. are not included because the companies are going to pay those costs anyway–talk to the people who got laid off or the creditors and service companies that didn’t get paid and see if those costs get paid anyway!
All the best,
Art
Hello Art,
Thanks for your article. I visit your website everyday for more insight. I was wondering when we will see a new article on natural gas. Last time you wrote, you had suggested that gas would double. Gas already rose close to $3. I am really keen to know what you feel about the path ahead.
Thank you for the article Art. What do you make of last week’s
withdraw from storage of natural gas? It was only the third ever
in the summer if I am correct. I know it was really hot, but was it
all weather related (demand) or some supply related too?
Do you expect to see this more frequently or just every once in
awhile when there is abnormally hot weather? Thank you sir
[…] will argue about potential and possible Permian resources and reserves preferring Pioneer CEO Scott Sheffield’s view of things to reality. I won’t debate them but the point is that Saudi Permian is a stretch based […]
[…] will argue about potential and possible Permian resources and reserves preferring Pioneer CEO Scott Sheffield’s view of things to reality. I won’t debate them but the point is that Saudi Permian is a stretch […]
[…] will argue about potential and possible Permian resources and reserves preferring Pioneer CEO Scott Sheffield’s view of things to reality. I won’t debate them but the point is that Saudi Permian is a stretch based […]
[…] will argue about potential and possible Permian resources and reserves preferring Pioneer CEO Scott Sheffield’s view of things to reality. I won’t debate them but the point is that Saudi Permian is a stretch […]
[…] will argue about potential and possible Permian resources and reserves preferring Pioneer CEO Scott Sheffield’s view of things to reality. I won’t debate them but the point is that Saudi Permian is a stretch based […]
Art: I assume the $/bbls cost are average cost based on all of the wells, new and those farther down the decline curve. Also, as some cost are fixed, like insurance, labor cost and etc. and not based on volumes, the lower the production on a single well, the higher the cost per bbls for that well. It seems like using average $/bbls cost would misrepresent terminal profitably of a single well? and therefore the economics of that wells, and therefore EUR, and therefore….. So to accurately project profitability of each individual well, seems to be the only way to understand what the values really are. If they can’t make money on each individual well, sees hard to make it up on volume.
So my question is this, how can I figure out what the fixed cost vs the cost based on volumes for each well as it declines in volume? Does that make sense?